1. Field of the Invention
The present invention relates to pressure transient testing of producing hydrocarbon (oil and gas) reservoirs, and more particularly to measuring formation flow capacity and phase mobility from pressure transient data under segregated oil and water flow conditions.
2. Description of the Related Art
Hydrocarbon reservoirs are typically considered to include those containing either oil, gas or both as recoverable hydrocarbons. A water phase coexists with hydrocarbons in almost all hydrocarbon reservoirs. Even when both oil and water coexist, these are nevertheless referred to as oil reservoirs. In a good oil reservoir, before any production of oil from the reservoir begins, an oil phase is the only mobile phase, while the water phase is at its residual saturation and is immobile.
As production continues, the water phase starts to break through towards the producing wells. As producing time progresses, the amount of water production rate increases, compared to the simultaneously declining oil production rate. The relative water-oil production rates are monitored at individual producing wells and quantified through a parameter known in the petroleum industry as “water cut ratio.” A water cut ratio, normally expressed in percentage, is defined as the ratio of water production rate to the total production rate (oil and water together) at the surface conditions. Any prolonged production at a very high water cut ratio might lead to a decision to abandon this producing well, and to drill another supplementary well for oil production in a region of the field, uninvaded by water.
In the presence of strong gravity forces in subsurface environments, having specific geometrical and petrophysical properties undergoing simultaneous flow of multiphase fluids, segregated flow mechanism of oil and water usually takes place. Under this flow mechanism, the heavier fluid, water phase in this case, tends to position itself at the lower zone of the reservoir, while the lighter fluid, oil phase, positions itself at the upper zone of the reservoir. A difference in density between the oil and water phases is the main driving force in the process of segregating the oil and the water phases. This process is boosted by the low, creeping velocity of fluids in the reservoir. The segregated flow mechanism is observed very often in a number of fields known to Applicant, especially in giant carbonate formations, where good mobility in both the vertical and horizontal directions of the reservoir is present.
Pressure-transient tests can be viewed as experiments that are conducted on producing oil wells to acquire certain information about its productivity and to characterize the in-situ properties of its near-wellbore reservoir region. Properties derived from such tests, also known as well tests, are very important in evaluating the reservoir productivity and the accessibility to the hydrocarbon reserves, in addition to providing ability to understanding and characterizing reservoir rocks and its dynamic behavior under in-situ conditions.
In typical well test operations, pressure and production rates are measured as functions of time, usually using high-resolution gauges, located either at surface or downhole. The pressure and rate responses from the well tests are then analyzed and interpreted by identifying flow regimes using appropriate well and reservoir models. Analyses of the data obtained from well tests, called pressure-transient analyses, have become increasingly sophisticated with many numerical and analytical approaches. Analyses of data from tests under segregated flow of oil and water are not accurate, because the analysis equations are based on the assumptions of single-phase flow.
The most widely accepted methodology to-date to analyze multiphase flow is what is referred to as the Perrine method or approach (Perrine, R. L., 1956. Analysis of pressure-buildup curves. Drilling and Production Practice, API, 482-509). This approach does not consider rigorously the segregated flow mechanism as encountered in the oil reservoirs in the presence of water. As the Perrine method considers effective properties due to the reservoir and the fluids under multi-phase conditions, it does not have the capability of estimating the true formation capacity. Thus, the Perrine method provides limited information for reservoir characterization. Al-Khalifa et al. have shown with examples of the way the Perrine method is utilized in extracting the reservoir parameters (Al-Khalifa, A. J., Horne, R. N. and Aziz, K., 1989. Multiphase Well Test Analysis: Pressure and Pressure-Squared Methods. Paper SPE 18803 presented at the SPE California Regional Meeting, Bakersfield, Calif., April 5-7).
Further, as far as is known, previous efforts (mainly the Perrine method) in the prior art treat the multiphase flow systems the same way irrespective of the specific flow regime in hand. These prior methods do not distinguish the segregated flow mechanism from the other mechanisms. The Perrine method can only extract very limited information, related to the values of mobility in oil and water phases. It thus does not have the capability of determining the true formation capacity (or equivalent dry oil flow capacity). This method provides an accurate method of extracting flow capacity and phase mobility under segregated flow of oil and water.